Process for the production of synthesis gas and clean fuels

ABSTRACT

The disclosure relates to the production of synthesis gas and clean fuels by the integration of fluid catalytic cracking and catalytic steam reforming. More particularly, the disclosure relates to a combination of process steps in which a heavy hydrocarbon oil is cracked in a heavy oil catalytic cracking unit to produce a cracked overhead effluent which is hydrogenated and the resulting saturated desulfurized effluent is reformed in a catalytic steam reforming unit to produce synthesis gas. Further, the disclosure relates to the production of substitute natural gas and to the production of substitute natural gas and low sulfur fuel oil by the multi-step processing of crude oil.

[ Jan. 28, 1975 [541 PROCESS FOR THE PRODUCTION OF 3,071,419 6/l972 Ireland et al 208/93 7 k 3,67l,422 6/l972 MUTI'OW SYNTHESIS GAS A 3.712.800 l/l973 Schutte.... 1 Inventors: James R. Murphy; Leland 3,726,789 4/1973 Kovach Schneider, both of Houston. Tex. 3,732,085 5/1973 Carr et a1 48/214 [73] Assignee: Pullman incorporated, Chicago, Ill.

' Primary [:xamincrS. Leon Bashore [22] Filed: 1972 Assistant lixuminerPeter F. Kratz [21] App]. No.: 304,508

[57] ABSTRACT [52] Cl 9 48/197 R1 48/213 The disclosure relates to the production of synthesis 48/2141 252/373. gas and clean fuels by the integration of fluid catalytic [5 Cl. t .t ra king and atalytic steam rcfo rming More purticul58l Fleld of Search 48/197 R, 213, larly, the disclosure relates to a combination of pro- 48/212, 215; 423/329; 208/153, 347, 70, 93; cess steps in which a heavy hydrocarbon oil is cracked 252/373 in a heavy oil catalytic cracking unit to produce a cracked overhead effluent which is hydrogenated and [56] References cued the resulting saturated desulfurized effluent is re- UNITED STATES PATENTS formed in a catalytic steam reforming unit to produce 2.998380 8/1961 McHenry etal 208 80 Synthesis g Further, h dis at s t h 3050,457 8/1962 Wilson 208/143 p oduction of substitute natural gas and to the produc- 3.329.627 7/1967 Gladrow et al. 423/329 tion of substitute natural gas and low sulfur fuel oil by 3,537.977 l l/l970 Smith 48/l97 R UX the muhi-gtep processing of crude iL $546,109 l2/l970 Woodle.... H 208/347 3.607127 9/1971 Pfieffer 208/153 18 Claims, 4 Drawing Figures 47 46 8 H r r VIRGIN NAPHTHA STEAM SYNTHESIS DESULFURIZATION PURIFICATION AND LIGHTER REFOFMER ZQS /2 REACTANT STEAM CRAIEKED REFLUX DRUM 35 EF LUENT DISTILLAT/ON 20 CONQENSER KX f UNIT 32 l /.DISENGAGING n 45 10 I7 ZONE 78 L f ,14 HOC u/v/r 36 HYDRO- l CARBON STRIPPER I9 I FEED \d 5- STEAM RING 21 i REFLUX I35 CRACKED RISER 'XX" 28 i GAS E S REACTOR I-&-FLUE GAS [CRACKED VCYCLONE 27 25 i 1 NAPHTHA Hg gggggg/A HEAVY rDIPLEG 26 f l 7 AND LIGHTER OIL HREGENERATING l 30 RISER FEED I5 ZONE 22 HYDROGEN" .2 5 ATION STEAM CO/LS L WATER l P FRACTIONATOR H 23 T 2 FLU/DIZ/NG I7 STEAM 29 33 REC YCLE cur in PROCESS FOR THE PRODUCTION OF SYNTHESIS GAS AND CLEAN FUELS This invention relates to the integration of fluid catalytic cracking of heavy hydrocarbon oils and catalytic steam reforming of light hydrocarbons to produce synthesis gas and clean fuels, such as substitute natural gas (SNG) and low sulfur fuel oils.

Due to the critical shortage of natural gas and other clean fuels, interest is centering on alternate means of producing them. Several processes of producing SNG from light hydrocarbons have been announced and some will go into commercial use. This has resulted in a shortage of light hydrocarbons for SNG production.

Crude oils and heavy hydrocarbon fractions are contaminated with sulfur compounds, nitrogen com pounds, organometallic compounds and high molecular weight carbonaceous hydrocarbons. These contaminated fractions require treatment for removal of these contaminants and in the usual refining process sequence they must be removed prior to the process steps employed to crack the heavy hydrocarbons to light hy drocarbons. Thus, a multitude of refining steps are usually required to obtain the light hydrocarbons used to produce SNG. One sequence designed to produce SNG and low sulfur fuel oil requires the use of a multitude of refining processes including hydrocracking, air separation, partial oxidation, solvent deasphalting and hydrodesulfurization (see, for example, Pipeline and Gas Journal", July, 1972).

The object of this invention is to provide a more efficient and less expensive processing sequence for providing synthesis gas and clean fuels. Another object of the invention is to integrate catalytic steam reforming with catalytic cracking to efficiently produce synthesis gas and clean fuels. A further object of the invention is to provide a process for producing the maximum quantity of catalytic steam reformer feedstock and SNG from whole crude oil.

Further objects and advantages of the process embodiments of the invention will be apparent from the following description, examples and drawings. Preferred embodiments of the invention are disclosed by the drawings in which:

FIG. I is a schematic diagram disclosing the broad combination of a heavy oil cracking unit which produces light hydrocarbons and steam and these are reacted in a catalytic steam reforming unit to produce synthesis gas;

FIG. 2, which is made up of FIG. 2A and FIG. 2B, is

a schematic diagram of an integrated process for producing the maximum amount of substitute natural gas by combining heavy oil cracking with steam reforming and other processing steps designed to maximize the production of SNG; and

FIG. 3 is a schematic diagram of an integrated process in which crude oil is separated and treated by heavy oil cracking, vacuum distillation, desulfurization and substitute natural gas preparation steps to produce substitute natural gas as well as low sulfur fuel oil.

In the first preferred embodiment of the invention, fluid catalytic cracking and catalytic steam reforming are integrated to produce synthesis gas.

The hydrocarbon feedstock to the catalytic cracking unit may be a crude oil, a topped petroleum or, a heavy hydrocarbon fraction derived from a petroleum refining step such as visbreaking, solvent deasphalting, hy-

drodesulfurization, delayed coking, fluid coking or from other hydrocarbon sources such as coal or shale oil. The catalytic cracking unit comprises a reaction zone and a catalyst regeneration zone and the catalyst is circulated between the first preferred embodiment of the two zones. According to the present invention, severe cracking conditions are employed whereby at least volume percent, preferably greater than percent 'and most preferably to percent of the cracking feed is cracked togas and light hydrocarbons boiling in the naphtha boiling range together with coke residue. The cracking unit is integrated with a steam reformer by treating these materials with hydrogen such that the cracked naphtha fraction and lighter materials may be passed to the catalytic steam reformer. Further integration can be provided by manufacturing steam in the catalyst regeneration zone of the cracking unit and passing this steam to the catalytic steam reformer as reactant steam. In steam reforming for every pound of naphtha reformed about 1 to 2 pounds of steam are required.

The catalytic steam reforming reaction is illustrated by the following idealized reaction between the normally liquid hydrocarbon, normalheptane and steam to produce hydrogen-containing gaseous product.

There are a number of 'side reactions and the reaction effluent includes carbon dioxide, methane, unreacted steam and carbon. The reaction is used to provide synthesis gas to be used in the production of ammonia, hydrogen, methanol, reducing gas or SNG.

Most steam reforming catalysts comprise nickel on a support and they are rapidly deactivated by sulfur compounds and by carbon derived from unsaturated materials in the feedstock. According to the present invention, suitable feed for catalytic steam reforming to produce synthesis gas, preferably SNG, is obtained by catalytic cracking of hydrocarbons and treating the cracked materials with hydrogen.

In the second preferred embodiment of the invention the process units are integrated to produce a maximum quantity of SNG from a wide boiling range hydrocarbon feedstock like whole crude oil which contains sulfur and metals. In this embodiment the feedstock is distilled to produce a liquid virgin naphtha fraction which is passed to an SNG unit. At least the major portion of the topped feedstock including recycle is cracked to gas and light hydrocarbons and following hydrogenation this material is passed to the SNG unit.

In the SNG unit the virgin light hydrocarbon fraction and the fraction obtained from catalytic cracking are steam reformed and further treated to maximize SNG such as by enriching the reforming products by methane enriched fractions. SNG units comprise a sequence of processing steps including desulfurization, steam reforming, methanation and impurity removal. Typical processing sequences are disclosed in Hydrocarbon Processing, April, 1971, pages 97, 98 and 99. This publication also gives details of specific processing steps which may be employed such as CO, and H 8 removal, pages 96, 117 and 120.

In the third preferred embodiment of the invention the process units are integrated to produce both SNG and low sulfur fuel oil from a wide boiling range hydrocarbon feedstock like whole crude oil which contains sulfur and metals. In this embodiment, the feedstock is distilled to provide a virgin naphtha and lighter fraction, a virgin gas oil and an atmospheric bottoms fraction. The virgin naphtha and lighter fraction is passed to the SNG plant. The virgin gas oil is hydrodesulfurized and the atmospheric bottoms fraction is divided into two parts. One part of the bottoms is cracked to produce SNG feedstock and the other part is treated by vacuum distillation and at least in part by catalytic hydrodesulfurization to produce fuel oil components. The various fuel oil components are then blended to produce low sulfur fueloil. Conventional hydrodesulfurization' processes are'employed on the various fractions to reduce the sulfur content.-Suitable hydrodesulfurization catalysts comprise one or more hydrogenation metals supported on a suitable carrier material. Salts of Group VI and Group VIII metals are preferred hydrogenating components, specifically oxides or metal sulfides of molybedenum, tungsten, cobalt, nickel and iron are used. Alumina, silica-alumina, bauxite and kieselguhr are suitable support materials.

Referring to FIG. 1, a hydrocarbon fraction is introduced by line to a distillation column 11. The fraction may contain from 0.1 to 8 weight percent sulfur and from 1 to 1000 ppm organo metallic compound such as compounds of vanadium and nickel. The asphaltene content of the fraction may range from 0.1 to 20 volume percent. A virgin naphtha and lighter frac tion is taken overhead by line 12 and aheavy bottoms fraction removed by line 13. The virgin naphtha fraction is a top cut from the crude having an end point up to about 400 F.; however, it is understood that this temperature is arbitrarily dependent in part upon the characteristics of the feed and in part upon catalysts and conditions to be employed in catalytic steam reforming operations. This fraction will contain sulfur compounds but it will be relatively free of organo metallic compounds and asphaltenes. Therefore, according to the present invention, while a virgin naphtha and lighter fraction may be a cut boiling up to 365 F., the

fraction may have an end point in the range from about 200 F. to about 450 F. The heavy oil bottoms fraction is the remainder or residuum of higher boiling materials of the crude oil. For example, the residuum may have 10 to 90 percent materials boiling above 600 F. The heavy oil bottoms fraction is introduced to a heavy oil cracking unit 14. The particular cracking catalyst utilized in the heavy oil cracking unit 14 is not critical to the present invention, but zeolite type cracking catalysts are preferred.

Cracking severity is controlled to provide feedstock conversion of at least 65 volume percent and preferably between 80 and 100 percent. Typical cracking conditions are set forth below in Table I.

TABLE I CATALYTIC CRACKING CONDITIONS Broad Preferred Temperature, F 850 1200 1050 Pressure, psig l0 50 30 Recycle Rate, Vol.%(FF) 0 100 50 Catalyst/Oil Ratio 3/1 15/1 6/1 Space Veloeity,wtlhr/wt 0.5 1000 200 The heavy oil cracking unit 14 preferably employs a riser reactor 15. The principal reaction zone of the cracking unit is preferably a riser line 16 which is a feature of a riser cracking unit like that shown and described in US. Pat. No. 3,607,127, issued Sept. 21, 1971. Conventional fluid cracking catalysts are employed including, for example, amorphous silicaalumina catalysts or molecular sieve (zeolite) matrixtype catalysts having an average particle size in the range of about 40 to about 100 microns. Zeolite catalysts are preferred. The heavy oil bottoms fraction is fed by line 13 into the bottom portion of riser 16 of the riser reactor 15 and is admixed with the cracking catalyst by means of fluidizing steam introduced by line 17. The riser should have a length to diameter ratio in the range of 3/1 to 30/1. In FIG. 1 a folded riser as more fully described in US. Pat. No. 3,607,127 is shown. From 50 to percent of the cracking reaction takes place in the riser l6 and the remainder of the cracking takes place in the disengaging zone 18 and the stripper 19. Cracked materials leaving the end of the folded riser disengage from the catalyst in zone 18 and pass upwardly through cyclones (not shown) for recovery. Catalyst and occluded uncracked feedstock pass downward through the disengaging zone to stripper 19. The stripper is fitted with suitable baffle means and a steam ring 21 adapted to strip occluded cracked effluent which passes overhead while the catalyst passes downwardly into the regeneration zone 22. In the regenerating zone 22, the catalyst is contacted with an oxygen containing gas at regeneration temperatures whereby the coke which is on the catalyst is burned off to the desired levels of residual coke on the regenerated cracking catalyst. Within the regenerating zone 22 are steam coils 23 adapted to remove heat from the catalyst. Water is introduced by line 24 into the steam coils wherein large amounts of steam are produced and removed byline 25. Within the regenerating zone 22 may be one or more dip legs 26. The gaseous products are separated in a cyclone 27 to remove any solids allowing a gas to be removed as flue gas by line 28 and the solids to be returned by dip leg 26. The regenerated catalyst is removed from the regenerating zone 22 by suitable valve means and feed devices (not shown) in a sump portion 29 of the riser reactor 15 to be reintroduced into the riser l6 and combined with the fluidizing steam and heavy oil bottoms fraction.

The effluent stream from the heavy oil cracking unit 14 is taken by line 20 to a fractionator 30. In the fractionator 30, a heavy oil recycle cut may be removed by line 31 which is combined with the heavy oil bottoms fraction in line 13 to be fed to the heavy oil cracking unit 14. The bulk of the cracked effluent stream is taken overhead by line 32 whereas a small bottoms fraction may be removed by line 33 which ultimately may be used as plant fuel. I

It will be noted that the separation in fractionator 30 is completely different from the conventional type of fractionation employed downstream of a typical petroleum refinery catalytic cracker. The products are separated into two major fractions rather than multiple fractions such as light hydrocarbons, gasoline, kerosene and middle distillates. This is because the process does not prepare precursors for alkylation, high octane reforming, domestic heating oils and the like.

The overhead fraction is passed through a condenser 34 and introduced to a reflux drum 35 to separate the gas stream from the liquid. The liquid cracked naphtha fraction is removed from the reflux drum 35 by line 36. A portion is taken by line 37 through valve 38 and introduced into the top of the fractionator 30 as a reflux stream. The liquid cracked naphtha fraction is then introduced into a hydrogenation unit 39 for treating the fraction with hydrogen introduced by line 40 to saturate the olefins and aromatics and to remove sulfur in the fraction. The severity of conditions in the hydrogenation unit 39 are such that the hydrogenated naphtha and lighter fraction is a suitable feed to be catalytically steam reformed. Suitable catalysts and conditions may be selected from those set forth elsewhere herein.

The gas fraction from the reflux drum 35 may be removed by line 41 wherein the gas is either utilized because of its high hydrogen content as a synthesis gas component or passed through valve 42 to a separation unit or may be passed through a suitable valve 43 compressed in compressor 44 to be introduced to the hydrogenation unit 39.

From the hydrogenation unit 39 is removed a hydrogenated cracked naphtha and lighter fraction by line 45 which is introduced to a catalytic steam reforming unit 46. The hydrocarbon feed to the catalytic steam reforming unit 46 may be the saturated cracked naphtha fraction alone or preferably this fraction in combination with the virgin naphtha from line 12 which has been desulfurized in a desulfurization unit 47 and then combined with the saturated cracked naphtha fraction. The product from the catalytic steam reforming unit 46 comprises 50 80% and 30% CO, along with smaller amounts of CO and CH and may be purified in purification unit 48 as a suitable synthesis gas product. Such a product may be useful to produce substitute natural gas, ammonia, methanol, hydrogen or other valuable products derived from synthesis gas.

Referring now to FIG. 2, this specific embodiment illustrates the maximized conversion of a crude oil feed into substitute natural gas according to the present invention. A desalted whole crude oil containing 1.71 percent sulfur is introduced by line 50 at the rate of 150 MED into a distillation column 51. A virgin naphtha and lighter fraction including propane and butane is removed overhead by line 52 at a rate of 39 MBD. A heavy oil fraction at a rate of 1 l1 MBD is removed by line 53 from the bottom of distillation column 51. The heavy oil bottoms fraction is introduced into a heavy oil cracking unit shown generally by reference numeral 54. The heavy oil cracking unit 56 is preferably a riser reactor shown generally by reference numeral 55. Cracking catalyst from the reactor 55 is combined with steam introduced by line 56 into the riser 57 wherein the heavy oil fraction is also introduced. The heavy oil bottoms fraction is catalytically cracked in the riser 57. The cracked hydrocarbons and cracking catalyst are separated in disengaging zone 58. Additional cracked hydrocarbons are formed due to stripping and cracking of occluded hydrocarbons on the catalyst in stripping zone 59. The cracked hydrocarbons pass through a cyclone 60 and are removed by line 61. Catalyst separated in the cyclone 60 is returned to the stripper via dip leg 62. In the stripping zone 59 may be baffle means 63 and a steam ring 64- to aid in removing hydrocarbons occluded on the catalyst. The cracking catalyst flows downwardly to a regenerating zone 65. In the regener ating zone the catalyst is contacted with air and the car- I bon which is contained on the catalyst is burned off to the desired level. In the regenerating zone 65 are steam coils 66. Water is introduced by line 67 wherein substantial amounts of steam are produced in the regenerating zone and removed by line 68. During the burning off of the carbon in the regenerating zone 65, flue gas is passed through a cyclone 69 and the flue gases removed by line 70 while catalyst fines are returned to the regenerator bed via dip leg 7E.

The effluent stream removed from the heavy oil cracking unit 58 by line 61 is passed to a fractionation tower '72. From the fractionating tower '72 a substantial portion of the fractionator product may be recycled by line 73 to a hydrogenation unit 74 before being passed by line 75 to be combined with the heavy oil bottoms fraction in feed line 53.

A very small fraction of the heavy bottoms from the fractionation unit 72 is removed by line 76 and line 77 for use as plant fuel or may be introduced as fuel to a CO boiler 78. The flue gases in line 70 from the regenerating zone 65 of the heavy oil cracking unit 54 are passed to the CO boiler 78 to produce steam which is removed by line 79 to be combined with the steam formed in the regenerating zone 65 and removed by line 68.

The desired naphtha-gas fraction is removed from the fractionator by line 88 and is passed to a gas-liquid separator 81. The liquid cracked naphtha fraction is removed by line 82 where it is passed to a hydrogenation unit 83. The hydrogen-rich gases are removed from the gas liquid separator 81 overhead wherein they are introduced into the hydrogenation unit 83 to hydrogenate the olefin hydrocarbons and aromatic hydrocarbons as well as to desulfurize the cracked naphtha fraction. Approximately two thirds of the hydrogen necessary for the hydrogenation may be obtained from the hydrogen produced in the heavy oil cracking unit and introduced by line 84. Additional hydrogen may be introduced by line 85. The hydrogenated cracked naphtha fraction is removed from the hydrogenation unit 83 by line 86 for introduction into a steam reforming unit 87 which is part of a substitute natural gas unit.

Thirty-nine MBD of virgin naphtha and lighter fraction from line 52 is introduced into a desulfurization unit 88 for desulfurization after which it is combined with 121 MED of hydrogenated cracked naphtha from line 86. A portion of the combined naphtha feed e.g. 40 to 60 percent is passed through line 89 containing a valve 90 for introduction into a hydrogasification unit 91. Likewise, the product from the steam reforming unit 87 is passed to the hydrogasification unit 91. A portion of the steam reforming unit product is removed by line 92 wherein it is utilized in the production of hydrogen in a hydrogen plant 93, the output of which may be introduced by line to the hydrogenation unit 83. The product obtained from the hydrogasification unit 91 which contains 50 methane is introduced into a methanation unit 94 for methane enrichment. The product is then passed through a carbon dioxide removal unit 95 to product a substitute natural gas product having a heating value of approximately 1,000 BTU. This specific embodiment illustrated in FIG. 2 beginning with a desalted whole crude oil feedstock produces MED naphtha for steam reforming and a SNG product which is recovered at a rate of about 780 million cubic feet per day.

The specific substitute natural gas process steps shown in FIG. 2 are'those preferred, however, there are other processes, all of which utilize catalytic steam reforming as an initial step that may be utilized as well. In the preferred substitute natural gas process, however, the general condition for carrying out the specific steps may be those which follow.

In the catalytic steam reforming step the catalytic steam reforming feedstock is converted to a hydrogenrich gas by reaction with steam. A catalyst is used which is usually a nickel catalyst and the reaction carried out in a fixed bed steam reformer. The catalyst contains nickel including elemental nickel or a compound of nickel such as nickel oxide, and mixtures thereof which is supported by a porous refractory material capable of maintaining high mechanical strength and possessing steam and high temperature stability. The preferred catalyst has a second ingredient, namely an added alkaline compound, of which, alkali metal compounds, including those of sodium, lithium, and potassium, are preferred. By utilizing the preferred catalyst the ratio of steam to hydrocarbon may be maintained at a ratio of about III to about 2/1 pounds of steam per pound of hydrocarbon. The conditions in the steam reformer are temperatures of about 450 to 500 C. and atmospheres. The product of the catalytic steam reforming step is a gas consisting of methane, hydrogen, carbon dioxide, carbon monoxide and excess water vapor. The preferred conditions and catalyst for the steam reforming step are set forth more fully in U.S. Pat. Nos. 3,119,667; 3,417,029; and 3,567,411.

The hydrogasification step as a processing step is a modification of a catalytic steam reforming operation in that it too is the reaction of steam and hydrocarbon utilizing a steam reforming catalyst. This step is operated at essentially the same operating pressures but at slightly lower temperatures. The reaction may also take place in a fixed bed similar to the catalytic steam reforming step. The hydrogasification step yields a gas of similar composition to that the the catalytic steam reforming step except that the methane content is higher and the excess steam lower. Suitable operating conditions for the hydrogasification step are a pressure of about 30 atmospheres and a temperature of about 370 C. to 450 C. A specific illustration of a suitable hydrogasification step is set forth in U.S. Pat. No. 3,625,665.

In the methanation step, gas from the hydrogasification step is cooled to condense the gases and separate the majority of the excess water vapor. The gas is then reheated, at essentially the same pressure, for example, 30 atmospheres, to a temperature of about 300 C. to 350 C. The gas is introduced into a fixed bed of nickel catalyst, where a reaction occurs to yield an equilibrium mixture, i.e. comprised primarily of methane and carbon dioxide, with small residual quantities of hydrogen and carbon monoxide.

In the carbon dioxide removal step, the gas from the methanator, maintained at about the same pressure and at a temperature of approximately 90 C., is contacted in a scrubber with an aqueous solution of potassium carbonate. Carbon dioxide reacts with the solution to form potassium bicarbonate, thereby removing most of the carbon dioxide from the gas. The scrubbed gas containing approximately 1% carbon dioxide is released from the scrubber. The rich solution is directed to a regenerator in which, at a lower pressure of about 2 atmospheres and a temperature of approximately 110 C., carbon dioxide is released by application of heat, thereby reconverting the solution to potassium carbonate. The regenerated solution is then recycled to the scrubber.

Referring to FIG. 3 of the drawings, a hydrocarbon feed is introduced by line 100 to a distillation unit 101. The hydrocarbon feed may be a crude oil containing 1.71 percent sulfur introduced at a rate of 150 MBD. Removed overhead from the distillation unit 101 is a naphtha fraction at a rate of 39 MBD by line 102. A light gas oil fraction boiling in the range of about 365 F. to about 650 F. is removed as a side cut by line 103 and is passed through a desulfurization unit 104 to produce a desulfurized light gas oil at a rate of 44 MBD and removed by line 105. Sixty-seven MBD of a heavy oil bottoms fraction is removed by line 106. A portion, 43 MBD, is introduced by line 107 to the heavy oil cracking unit 108. The remaining portion, 24 MBD, is introduced to a vacuum distillation unit 109.

In the specific embodiment illustrated in FIG. 3, the combination of the heavy oil cracking unit with the production of a suitable naphtha fracton for a catalytic steam reforming unit is adapted to produce both a substitute natural gas product and a low sulfur fuel oil. Thus, the heavy oil bottoms introduced to the heavy oil cracking unit 108 is converted at conversions between and percent utilizing the severe conditions set forth hereinabove, to produce an effluent stream 110 which is introduced into a fractionation unit 111. The very high conversions are obtained by taking a fraction from the fractionation unit 111 by line 112 and recycling it with the heavy oil bottoms fraction introduced by line 107 to the heavy oil cracking unit 108. The cracked naphtha fraction is removed from the top of the fractionation unit 111 by line 113 and introduced into a gas-liquid separation unit 114 after being passed through a condenser (not shown). The liquid cracked naphtha fraction is removed by line 115 and introduced into a hydrogenation unit 116. The gas fraction from the gas-liquid separation unit 114 is rich in hydrogen and may be utilized in the hydrogenation unit 116 and introduced by line 117. Sulfur is removed from the cracked naphtha fraction by hydrodesulfurization in unit 116. Hydrogen sulfide is removed by line 118. Also within the hydrogenation unit 116 saturation of the olefin hydrocarbons and aromatic hydrocarbons present occurs so as to produce a sweet hydrogenated cracked naphtha fraction which is removed by line 119 to be introduced into the substitute natural gas plant 120 which contains a catalytic steam reforming unit as the first of several process steps. According to present technol gy, the SNG plant feedstock would contain very low olefins (less than 1 2%) and low sulfur (50 to 500 ppm), aromatics (less than 25%), naphthenes (less than 40%), with preferrably as much saturated hydrocarbons as possible, i.e. 50 100%. The SNG plant is more fully illustrated with regard to the production of substitute natural gas in FIG. 2, as described hereinbefore. The hydrogenated cracked naphtha fraction amounting to 43 MBD is combined with 39 MBD of virgin naphtha fraction in line 102 to be treated and produce the substitute natural gas product of this embodiment. The steam used as a reactant in the steam reforming unit is that steam formed in the regeneration unit and removed by line 121 of the heavy oil cracking unit 108 as described hereinbefore.

For the production of the low sulfur fuel oil, a portion is obtained from the overhead of the vacuum distillation unit 109 taken at a rate of 16 MBD by line 122 which is introduced into a desulfurization unit 123. Combined with the overhead from the vacuum distillation unit 109 is the bottoms from the fractionation unit 111 taken by line 124 and introduced into the hydrodesulfurization unit 123. In the hydrodesulfurization unit 123, hydrogen sulfide is produced which is removed by line 125 and sent to a sulfur recovery unit 126. The hydrogen sulfide produced in the naphtha hydrogenation unit 116 and removed by line 118 may also be combined and sent'to the sulfur recovery unit 126. The unit 126 produces sulfur at the rate of 190 tons per day. The Claus process may be used for this purpose.

The streams of desulfurized hydrocarbon oils may then be blended. Namely, the light gas oil which has been desulfurized and removed by the line 105 may be combined with the heavy gas oil which has been desulfurized and removed by line 127 and with the bottom fraction from the vacuum distillation unit 109 from line 128 to be combined'to form a low sulfur fuel oil in line 129. at therate of about 76 MBD at a sulfur level of about 0.68 percent. It will be noted that FIG. 3 discloses three hydrodesulfurization units designed by reference numerals 104, 116 and 123. The embodiment of FIG. 2 discloses hydrogenation in the units designated by reference numerals 74, 83 and 88. FIG. 1 discloses hydrogenation in the unit designated by reference numeral 39. The hydrotreating or hydrodesulfurization step carried out on a particular fraction may perform several functions including hydrodesulfurization, hydrosweetening, saturation of olefins and aromatics, hydrodenitrogenation, etc. Catalyst andreaction conditions are selected in accordance with the characteristics of the feed to be treated and the degree of severity required to obtain a fully treated product. Temperatures ranging from 450 F. to 850 F. are suitable. Pressures ranging from 50 to 2000 psig may be employed. Hydrogengas rates in the range of 100 to 2000 SCF/bbl are suitable. The preferred hydrotreating catalysts comprise one or more hydrogenation metals supported on a suitable carrier material. Oxides or sulfides of molybedenum, tungsten, cobalt, nickel, and iron supported on such supports as alumina and silicaalumina are used. The most preferred catalysts are cobalt molybdate on alumina and nickel molybdate on alumina. The catalyst can be employed in the form of a fixed bed or a fluidized bed. Liquid phase or mixed phase conditions can be used. It may be desirable to blend fractions or parts of fractions for hydrogen treatment. Hydrogen-containing gases having a hydrogen content of 60 to 100 percent are suitable and it is a feature of this invention that hydrogen produced in the heavy oil cracking unit may be employed as a source of reactant hydrogen. A number of hydrogen treating processes of varying degrees of severity are disclosed in .Hydrocarbon Processing, September, 1972, pages 150 184.

The sulfur recovery units designated by reference numeral 126 may be any conventional process for the conversion of hydrogen sulfide to sulfur, such as the Stretford Process described in Hydrocarbon Processing, April, 1971, page 119, and the modified Claus Process disclosed in Hydrocarbon Processing, April, 1971, at page 112.

Thus, the process embodiments of the present invention provide a means for the conversion of hydrocarbons to clean fuels. A whole crude oil containing substantial amounts of sulfur and metals can be converted to desirable products such as very high (e.g. 900 1000) BTU substitute natural gas and fuel oil containing less than one percent sulfur. The heavy oil catalytic cracking concept of the present invention is unique in that a heavy hydrocarbon may be converted and treated to a steam reforming feedstock. The fact that the catalyst becomes contaminated with carbon and metals such as vanadium, nickle and iron does not severely reduce the activity and life of the catalyst for the type of high-severity cracking employed. It is understood that in the catalytic cracking unit, fresh catalyst is added as necessary. The addition may be continuous or intermittant.

The embodiments of the invention are essentially self-supporting from an energy balance standpoint. The heavy oil cracking unit provides very large quantities of steam which can be used as reactant steam in the catalytic steam reforming process. The feed to the heavy oil cracking unit feedstock may be recycled to extinction if desired or a portion of the recycle material can be used as plant fuel. The quantity of hydrogen required to saturate and to desulfurize the: various intermediate fractions produced in the preferred embodiments is much less than the quantity of hydrogen which would be required to support a hydrocracking unit and associated hydrodesulfurization units.

Obvious variations of process embodiments disclosed in the descriptions and drawings which would have occurred to those skilled in the art are intended to be included within the scope of the disclosure and claims.

We claim: 1. A process for the production of synthesis gas which comprises:

introducting a hydrocarbon feedstock into a catalytic cracking zone in the presence of fluidized cracking catalyst under severe fluid cracking conditions including at least 65 percent conversion of said hydrocarbon feedstock to produce an effluent;

fractionating said effluent to obtain a cracked naphtha fraction;

hydrogenating said cracked naptha fraction with hydrogen to saturate olefins and aromatics to produce a more saturated cracked naphtha fraction; and

introducing said more saturated cracked naphtha fraction and steam to a catalytic steam reforming unit to produce synthesis gas. 2. A process according to claim 1 wherein said conversion is between and percent.

3. A process according to claim 1 wherein said cracking catalyst is a zeolite catalyst.

4. A process according to claim 1 wherein said fractionating of said effluent produces a heavy fraction which is recycled to said catalytic cracking zone.

5. A process according to claim 1 wherein said fractionating of said effluent produces a gas fraction rich in hydrogen which is used in hydrogenating said cracked naphtha fraction.

6. An integrated process for the production of substitute natural gas which comprises:

cracking a hydrocarbon feedstock in a fluid catalytic cracking zone of a heavy oil fluid cracking unit in the presence of fluid cracking catalyst at conversions of 75 to 100 percent to produce an effluent;

fractionating said effluent to obtain a cracked naphtha fraction;

hydrogenating said cracked naphtha fraction with hydrogen to saturate olefins and aromatics to produce a more saturated cracked naphtha fraction;

introducing said more saturated cracked naphtha fraction and steam to a catalytic steam reforming unit to produce a steam reforming effluent containing methane, hydrogen, CO and CO and enriching said steam reforming effluent to increase the proportion of methane in the substitute natural gas product.

7. An integrated process according to claim 6 wherein said enriching includes blending of said steam reforming effluent with methane enriched fractions.

8. An integrated process according to claim 6 wherein said enriching includes the steps of hydrogasification, methanation and carbon dioxide removal.

9. An integrated process for the production of substitute. natural gas from hydrocarbon feedstock which comprises:

distilling said hydrocarbon feedstock into a virgin naphtha fraction and a heavy oil bottoms fraction containing sulfur and metallic components; cracking the heavy oil bottoms in a riser catalytic cracking zone of a heavy oil cracking unit in the presence of cracking catalyst at conversions of at least 65 volume percent to obtain an effluent;

fractionating said effluent to obtain a cracked naphtha fraction;

hydrogenating said cracked naphtha fraction with hydrogen to hydrogenate unsaturated components in the cracked naphtha;

blending said hydrogenated cracked naphtha fraction with said virgin naphtha fraction; introducing the blend together with steam to a catalytic steam reforming unit to produce a steam reforming effluent containing methane, hydrogen, CO and CO and enrichingsaid steam reforming effluent to increase the proportion of methane in the substitute natural gas product.

10. An integrated process according to claim 9 wherein said hydrocarbon feedstock is a crude petroleum oil.

11. An integrated process according to claim 9 wherein said virgin naphtha fraction is a fraction boiling up to 365 F.

12. An integrated process for the production of synthesis gas which comprises:

introducing a hydrocarbon feedstock into a fluid catalytic cracking zone of a heavy oil fluid catalytic cracking unit in the presence of a fluid cracking catalyst having an average particle size in the range of about 4.0 to about 100 microns to produce an effluent stream,

regenerating said fluid cracking catalyst in a regenerating zone having steam coils wherein large amounts of steam are produced;

recovering a cracked naphtha fraction from said effluent stream; hydrogenating said cracked naphtha fraction with hydrogen to saturate olefins and aromatics to produce a more saturated cracked naphtha fraction and introducing said more saturated cracked naphtha fraction and said steam produced in said regenerating zone to a catalytic steam reformer at steam reforming conditions to produce a synthesis gas.

13. An integrated process according to claim 12 in which said steam produced in said steam coils in said regenerating zone comprises 50 of the steam required for said catalytic steam reformer.

14. An integrated process according to claim 12 wherein said synthesis gas containing hydrogen and CO is further treated to concentrate the hydrogen.

15. An integrated process for the production of synthesis gas and fuel oil from a hydrocarbon feedstock which comprises;

a. distilling said hydrocarbon feedstock into a virgin naphtha fraction, a light gas oil fraction and a heavy oil bottoms fraction;

b. cracking a portion of said heavy oil bottoms fraction in a fluid catalytic cracking zone in the presence of a cracking catalyst to produce an effluent;

c. fractionating said effluent to produce a cracked naphtha fraction;

d. hydrogenating said cracked naphtha fraction with hydrogen to produce a desulfurized, hydrogenated cracked naphtha fraction;

e. combining virgin naphtha from said virgin naphtha fraction of (a) with naphtha from said desulfurized, hydrogenated cracked naphtha fraction of (d); and

f. introducing said combined fractions together with steam to a catalytic steam reformer to produce synthesis gas.

16. An integrated process according to claim 15 wherein said cracking catalyst is regenerated in a regenerating zone of said fluid catalytic cracking unit having steam coils wherein steam is produced; and

introducing said steam produced in said regenerating zone to said catalytic steam reformer of (f).

17. An integrated process according to claim 15 wherein said fractionating of said effluent of (c) produces a gas rich in hydrogen; and

said gas rich in hydrogen in used in hydrogenating said cracked naphtha fraction of (d).

18. An integrated process according to claim 15 wherein light gas oil from said light gas oil fraction of (a) is blended with the remaining portion of said heavy oil bottoms fraction to produce a fuel oil. 

1. A PROCESS FOR THE PRODUCTION OF SYNTHESIS GAS WHICH COMPRISES: INTRODUCING A HYDROCARBON FEEDSTOCK INTO A CATALYTIC CRACKING ZONE IN THE PRESENCE OF FLUIDIZED CRACKING CATALYST UNDER SEVERE FLUID CRACKING CONDITIONS INCLUDING AT LEAST 65 PERCENT CONVERSION OF SAID HYDROCARBON FEEDSTOCK TO PRODUCE AN EFFLUENT; FRACTIONATING SAID EFFLUENT TO OBTAIN A CRACKED NAPHTHA FRACTION; HYDROGENATING SAID CRACKED NAPTHA FRACTION WITH HYDROGEN TO SATURATE OLEFINS AND AROMATICS TO PRODUCE A MORE SATURATED CRACKED NAPHTHA FRACTION; AND INTRODUCING SAID MORE SATURATED CRACKED NAPHTHA FRACTION AND STEAM TO A CATALYTIC STEAM REFORMING UNIT TO PRODUCE SYNTHESIS GAS.
 2. A process according to claim 1 wherein sAid conversion is between 80 and 100 percent.
 3. A process according to claim 1 wherein said cracking catalyst is a zeolite catalyst.
 4. A process according to claim 1 wherein said fractionating of said effluent produces a heavy fraction which is recycled to said catalytic cracking zone.
 5. A process according to claim 1 wherein said fractionating of said effluent produces a gas fraction rich in hydrogen which is used in hydrogenating said cracked naphtha fraction.
 6. An integrated process for the production of substitute natural gas which comprises: cracking a hydrocarbon feedstock in a fluid catalytic cracking zone of a heavy oil fluid cracking unit in the presence of fluid cracking catalyst at conversions of 75 to 100 percent to produce an effluent; fractionating said effluent to obtain a cracked naphtha fraction; hydrogenating said cracked naphtha fraction with hydrogen to saturate olefins and aromatics to produce a more saturated cracked naphtha fraction; introducing said more saturated cracked naphtha fraction and steam to a catalytic steam reforming unit to produce a steam reforming effluent containing methane, hydrogen, CO and CO2; and enriching said steam reforming effluent to increase the proportion of methane in the substitute natural gas product.
 7. An integrated process according to claim 6 wherein said enriching includes blending of said steam reforming effluent with methane enriched fractions.
 8. An integrated process according to claim 6 wherein said enriching includes the steps of hydrogasification, methanation and carbon dioxide removal.
 9. An integrated process for the production of substitute natural gas from hydrocarbon feedstock which comprises: distilling said hydrocarbon feedstock into a virgin naphtha fraction and a heavy oil bottoms fraction containing sulfur and metallic components; cracking the heavy oil bottoms in a riser catalytic cracking zone of a heavy oil cracking unit in the presence of cracking catalyst at conversions of at least 65 volume percent to obtain an effluent; fractionating said effluent to obtain a cracked naphtha fraction; hydrogenating said cracked naphtha fraction with hydrogen to hydrogenate unsaturated components in the cracked naphtha; blending said hydrogenated cracked naphtha fraction with said virgin naphtha fraction; introducing the blend together with steam to a catalytic steam reforming unit to produce a steam reforming effluent containing methane, hydrogen, CO and CO2; and enriching said steam reforming effluent to increase the proportion of methane in the substitute natural gas product.
 10. An integrated process according to claim 9 wherein said hydrocarbon feedstock is a crude petroleum oil.
 11. An integrated process according to claim 9 wherein said virgin naphtha fraction is a fraction boiling up to 365* F.
 12. An integrated process for the production of synthesis gas which comprises: introducing a hydrocarbon feedstock into a fluid catalytic cracking zone of a heavy oil fluid catalytic cracking unit in the presence of a fluid cracking catalyst having an average particle size in the range of about 40 to about 100 microns to produce an effluent stream, regenerating said fluid cracking catalyst in a regenerating zone having steam coils wherein large amounts of steam are produced; recovering a cracked naphtha fraction from said effluent stream; hydrogenating said cracked naphtha fraction with hydrogen to saturate olefins and aromatics to produce a more saturated cracked naphtha fraction and introducing said more saturated cracked naphtha fraction and said steam produced in said regenerating zone to a catalytic steam reformer at steam reforming conditions to produce a synthesis gas.
 13. An integrated process according to claim 12 in which said steam produced in said steam coils in said regenerating zone comprisEs 50 - 100% of the steam required for said catalytic steam reformer.
 14. An integrated process according to claim 12 wherein said synthesis gas containing hydrogen and CO is further treated to concentrate the hydrogen.
 15. An integrated process for the production of synthesis gas and fuel oil from a hydrocarbon feedstock which comprises; a. distilling said hydrocarbon feedstock into a virgin naphtha fraction, a light gas oil fraction and a heavy oil bottoms fraction; b. cracking a portion of said heavy oil bottoms fraction in a fluid catalytic cracking zone in the presence of a cracking catalyst to produce an effluent; c. fractionating said effluent to produce a cracked naphtha fraction; d. hydrogenating said cracked naphtha fraction with hydrogen to produce a desulfurized, hydrogenated cracked naphtha fraction; e. combining virgin naphtha from said virgin naphtha fraction of (a) with naphtha from said desulfurized, hydrogenated cracked naphtha fraction of (d); and f. introducing said combined fractions together with steam to a catalytic steam reformer to produce synthesis gas.
 16. An integrated process according to claim 15 wherein said cracking catalyst is regenerated in a regenerating zone of said fluid catalytic cracking unit having steam coils wherein steam is produced; and introducing said steam produced in said regenerating zone to said catalytic steam reformer of (f).
 17. An integrated process according to claim 15 wherein said fractionating of said effluent of (c) produces a gas rich in hydrogen; and said gas rich in hydrogen in used in hydrogenating said cracked naphtha fraction of (d).
 18. An integrated process according to claim 15 wherein light gas oil from said light gas oil fraction of (a) is blended with the remaining portion of said heavy oil bottoms fraction to produce a fuel oil. 